Overview
We are an independent energy company engaged in the exploration, development and production of natural gas and oil in the U.S. Our principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties with an emphasis on unconventional natural gas reserves, such as shale resource plays. We are currently pursuing the development of liquids-rich natural gas in the Marcellus Shale play in the Appalachia area of West Virginia and central and southwestern Pennsylvania. We also hold prospective acreage in the deep Bossier gas play in the Hilltop area of East Texas and in the Mid-Continent area of the U.S.
Parent is a Canadian corporation, incorporated in Alberta in 1987 and subsisting under the Business Corporations Act (Alberta), with its common shares listed on the NYSE MKT under the symbol "GST." Parent is a holding company. Substantially all of the Company's operations are conducted through, and substantially all of its assets are held by, Parent's primary operating subsidiary, Gastar USA, and its subsidiaries. Gastar USA's Series A Preferred Stock is listed on the NYSE MKT under the symbol "GST.PRA."
Our current operational activities are conducted primarily in the U.S. As of June 30, 2012, our major assets consist of approximately 108,100 gross (75,700 net) acres in the Marcellus Shale in West Virginia and southwestern Pennsylvania, approximately 38,500 gross (20,300 net) acres in the Bossier play in the Hilltop area of East Texas and approximately 20,300 gross (9,900 net) acres in the Mid-Continent area of the U.S.
The following discussion addresses material changes in our results of operations for the three and six months ended June 30, 2012 compared to the three and six months ended June 30, 2011 and material changes in our financial condition since December 31, 2011. This discussion should be read in conjunction with our condensed consolidated financial statements and

the notes thereto included in Part I. Item 1. "Financial Statements" of this report, as well as our 2011 Form 10-K, which includes important disclosures regarding our critical accounting policies as part of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." 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.
Natural Gas and Oil Activities
The following provides an overview of our major natural gas and oil projects. While actively pursuing specific exploration and development activities in each of the following areas, there is no assurance that new drilling opportunities will be identified or that any new drilling opportunities will be successful if drilled.
Marcellus Shale and Other Appalachia. The Marcellus Shale is Devonian aged shale that underlies much of the Appalachian region of Pennsylvania, New York, Ohio, West Virginia and adjacent states. The depth of the Marcellus Shale and its low permeability make the Marcellus Shale an unconventional exploration target in the Appalachian Basin. Advancements in horizontal drilling and stimulation have produced promising results in the Marcellus Shale. These developments have resulted in increased leasing and drilling activity in the area. As of June 30, 2012, our acreage position in the play was approximately 108,100 gross (75,700 net) acres. We refer to the approximately 46,400 gross (20,800 net) acres reflecting our interest in our Marcellus Shale assets in West Virginia and Pennsylvania subject to the Atinum Joint Venture described below as our Marcellus West acreage. We refer to the approximately 61,700 gross (54,900 net) acres in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, West Virginia as our Marcellus East acreage. The entirety of our acreage is believed to be in the core, over-pressured area of the Marcellus play.
On September 21, 2010, we entered into the Atinum Joint Venture pursuant to a purchase and sale agreement with Atinum. Pursuant to the agreement, at the closing of the transaction on November 1, 2010, we assigned to Atinum, for $70.0 million in total consideration, an initial 21.43% interest in all of our existing Marcellus Shale assets in West Virginia and Pennsylvania, consisting of certain undeveloped acreage 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 us approximately $30.0 million in cash upon closing. Additionally, Atinum was obligated to fund its 50% share of drilling, completion and infrastructure costs, and paid an additional $40.0 million of drilling costs in the form of a drilling carry obligation by funding 75% of our 50% share of those same costs. Upon completion of the funding of the drilling carry, we made additional assignments in early 2012, as necessary, to Atinum as a result of which Atinum now owns a 50% interest in the Atinum Joint Venture Assets.
The Atinum Joint Venture's initial three-year development program called for the partners to drill a minimum of 12 horizontal wells in 2011 and 24 horizontal wells in each of 2012 and 2013. Due to recent natural gas price declines, Atinum and Gastar USA initially agreed to reduce the 2012 minimum wells to be drilled requirement from 24 wells to 20 wells. Atinum and Gastar USA subsequently agreed to extend the rig contract to May 2013 in the Marcellus Shale resulting in a plan to drill and complete approximately 23 gross (11.2 net) wells during 2012. During the six months ended June 30, 2012, we drilled and cased 12 gross (5.9 net) operated wells, completed fracture stimulation operations on 12 gross (5.5 net) operated wells and were in the process of fracture stimulating five gross (2.5 net) operated wells in Marshall County, West Virginia. We were also in various stages of drilling on nine gross (4.4 net) operated wells in Marshall County, West Virginia. All of our 2012 Marcellus Shale well operations were under the Atinum Joint Venture. As of June 30, 2011, Atinum has the right to participate in any future leasehold acquisitions made by us within Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia, on terms identical to those governing the existing Atinum Joint Venture. We will act as operator and are obligated to offer any future lease acquisitions to Atinum on a 50/50 basis. Atinum will pay us 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.
In December 2010, we completed a Marcellus Shale leasehold acquisition for the Marcellus East acreage for an aggregate purchase price of $28.9 million. The acquisition consisted of undeveloped leasehold in the Marcellus Shale concentrated in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, West Virginia, including a gathering system comprised of 41 miles of four and six inch steel pipeline, a salt water disposal well, and five conventional producing wells. The Marcellus East acreage was outside the initial AMI with Atinum, and Atinum elected not to acquire a 50% interest as provided under the terms of the Atinum Joint Venture. We believe their decision was due to the timing of the transaction and limited prior operational results within the initial Atinum Joint Venture AMI. We have completed the drilling of the Hickory Ridge 2H horizontal Marcellus well in Marcellus East in Preston County, West Virginia. We completed the 2,500 foot lateral with a ten-stage fracture stimulation in August 2011 and to date, the well has recovered approximately 58% of the fluids used in its completion. Nearby vertical wells experienced low gas rates prior to recovering at least 75% of completion fluids. We have installed a compressor to assist with accelerating the recovery of the completion fluids from the well. Due to the current natural gas price environment, we are currently not planning to drill any additional wells on the Marcellus East acreage during 2012.
As of June 30, 2012, our operated wells capable of production in Marshall County, West Virginia were comprised of 18 gross (7.8 net) producing wells and two gross (0.9 net) shut-in wells. The 18 gross operated wells on production were

comprised of three Accettolo wells, four Corley wells, five Hendrickson wells, three Simms wells and three Hall wells. Our average working interest in these 18 producing wells is 43.5% (net revenue interest 37.2%) and the average well lateral length is approximately 4,700 feet. The Accettolo 1H, 2H and 3H wells were placed on production in late June 2012 and our average working interest in these wells is 50.0% (net revenue interest 40.2%) and the average well lateral length is approximately 4,600 feet. The Wengerd 1H and 7H wells were shut-in to accommodate the current drilling of five additional Wengerd horizontal wells on the pad, discussed in further detail below.
As of June 30, 2012, we were commencing fracture stimulation operations on four gross (2.0 net) operated Wayne wells and one gross (0.5 net) operated Burch Ridge wells. Our average working interest in the Wayne wells is 50.0% (net revenue interest 40.6%) and the average well lateral length is approximately 5,500 feet. Our average working interest in the Burch Ridge wells is 50.0% (net revenue interest 41.5%) and the average well lateral length is approximately 5,400 feet.
As of June 30, 2012, we had drilling operations at various stages on ten gross (4.9 net) operated wells on the Wengerd and Shields leases. Top-hole drilling was commenced on two gross Wengerd wells, the 3H and 5H. We expect that drilling and completion operations on these two wells, as well as three additional Wengerd wells, will be completed by December 2012 and that all Wengerd wells will be turned to production at that time, including the two Wengerd wells shut-in during the second quarter. Our average working interest in the Wengerd wells is 44.5% (net revenue interest 37.7%) and the average well lateral length is targeted to be approximately 5,000 feet. Top-hole drilling was commenced on eight gross Shields wells on a ten horizontal well pad in Marshall County, West Virginia. We will resume horizontal drilling operations on the Shields wells later this year, and all ten Shields wells are scheduled for production in August 2013. Our average working interest in the Shields wells is approximately 50.0% (net revenue interest 42.0%) and the average well lateral length for the Shields wells is targeted to be approximately 2,800 feet.
Currently, we have commenced top-hole drilling operations on four gross (2.0 net) operated wells on the Lily lease in Marshall County, West Virginia. The Lily wells are scheduled to begin production by first quarter 2013. Our average working interest in the Lily wells is 50.0% (net revenue interest 40.6%) and the average well lateral length is approximately 5,200 feet.
As of June 30, 2012, we had participated on a non-operated basis in the drilling of seven horizontal Marcellus Shale wells in Butler County, Pennsylvania and an additional four non-operated horizontal Marcellus Shale wells in Marshall County, West Virginia. Three of the seven Butler County wells were turned to production on December 1, 2011 with the remaining four wells completed and turned to sales in March 2012. Our average working interest in the Butler County non-operated wells is 19.2% (net revenue interest 15.9%) and the average lateral length of the wells is 3,900 feet. Of the four Marshall County non-operated wells, two of the wells were on production prior to December 31, 2011 and the remaining wells were placed on production by mid-April 2012. Our current average working interest in the Marshall County non-operated wells is 21.4% (net revenue interest 18.6%) and the average well lateral length is approximately 4,200 feet. For the three and six months ended June 30, 2012, net production from the Marcellus Shale averaged approximately 20.7 MMcfe/d and 17.3 MMcfe/d, respectively, compared to 0.6 MMcfe/d for the three and six months ended June 30, 2011, respectively. During the last several quarters, our operated production and sales in West Virginia have been curtailed by issues with condensate handling, dehydration limitations and high line pressures on a third-party-operated gathering system. The gathering system operator has been gradually resolving these issues and the majority of the issues were resolved by the end of May 2012 by increasing dehydration capacity to 70 MMcf/d from 40 MMcf/d and adding compression to reduce line pressure to approximately 550 psi at the Corley CRP. An additional CRP is to be constructed at the Burch Ridge pad and will have 75 MMcf/d dehydration capacity and compression to ensure line pressures are maintained at approximately 550 psi. The Burch Ridge CRP is currently scheduled to be operational by before year-end 2012. If the Burch Ridge CRP is delayed, we may have to restrict our production in the fourth quarter of 2012 until the Burch Ridge CRP is operational. Hilltop Area, East Texas. At June 30, 2012, we held leases covering approximately 38,500 gross (20,300 net) acres in the Bossier play in the Hilltop area of East Texas in Leon and Robertson Counties. Wells in this area target multiple potentially productive natural gas formations and are typically characterized by high initial production and attractive long-lived per well reserves. Due to current low natural gas prices, we have suspended all Bossier drilling activities in the Hilltop area for 2012. We are monitoring offset horizontal drilling activity in the Eagle Ford and Woodbine formations by Encana Corporation, EOG Resources, Inc. and other companies. Should the drilling results of the offset operators warrant such, we may consider drilling an Eagle Ford or Woodbine test well in 2013.
For the three and six months ended June 30, 2012, net production from the Hilltop area averaged approximately 13.7 MMcfe/d and 13.9 MMcfe/d, respectively, compared to 16.6 MMcfe/d and 18.5 MMcfe/d for the three and six months ended June 30, 2011, respectively. The decline in production is the result of natural field decline and the suspension of our East Texas drilling plans as a result of low natural gas prices.
Mid-Continent Horizontal Oil Play. At June 30, 2012, we held leases covering approximately 20,300 gross (9,900 net) acres in the previously announced non-operated Mid-Continent horizontal oil play. Our leasing activities are continuing with a goal of leasing at least 25,000 gross acres in an initial AMI. In late July 2012, drilling operations commenced on the first of

three wells in this play to be drilled during 2012. The first well is targeted to have a horizontal lateral of approximately 4,200 feet and, if successful, should be completed by September 2012. Gross costs to drill and complete the first well are $4.3 million of which we are paying 62.5% ($2.7 million net) to earn a 50% working interest. Drilling operations on the second well are anticipated to commence in early fourth quarter 2012. The third well on the initial prospect should be spudded by December 2012. We will be paying 62.5% of the first four wells' gross drill and complete costs to earn a 50% working interest. For all future wells in the initial prospect area, we will be responsible for paying only our 50% working interest (approximate net revenue interest 39.0%).
Coalbed Methane - Powder River Basin, Wyoming and Montana. On May 3, 2012, we assigned our working interest in the Powder River Basin to the operator effective January 1, 2012.
Gastar USA Series A Preferred Stock
During the six months ended June 30, 2012, Gastar USA sold 2,022,762 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $38.5 million, resulting in 3,387,305 total shares issued for net proceeds of $65.8 million at June 30, 2012. From July 1, 2012 to August 3, 2012, we sold an additional 253,842 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $4.7 million. We plan to continue issuing Series A Preferred Stock under the ATM Agreement in the future depending on market conditions and our capital expenditures program. See "Liquidity and Capital Resources" of this report.

Results of Operations
The following is a comparative discussion of the results of operations for the periods indicated. It should be read in conjunction with the condensed consolidated financial statements and the related notes to the condensed consolidated financial statements found elsewhere in this report. The following table provides information about production volumes, average prices of natural gas and oil and operating expenses for the periods indicated:

                                              For the Three                   For the Six
                                               Months Ended                   Months Ended
                                                 June 30,                       June 30,
                                           2012            2011           2012            2011
Production:
Natural gas (MMcf)                           2,564          1,634           4,801          3,600
Oil (MBbl)                                      38             11              65             21
NGLs (MBbl)                                     62              -             110              -
Total production (MMcfe)                     3,169          1,697           5,847          3,728
Total (Mmcfe/d)                               34.8           18.6            32.1           20.6
Average sales price per unit:
Natural gas per Mcf, excluding impact  $      1.70     $     3.52     $      1.82     $     3.43
of realized hedging activities
Natural gas per Mcf, including impact         2.61           4.59            2.83           4.60
of realized hedging activities
Oil per Bbl, excluding impact of             56.72          96.66           64.03          92.30
realized hedging activities
Oil per Bbl, including impact of             62.76          96.66           66.42          92.30
realized hedging activities
NGLs per Bbl, excluding impact of            25.44              -           31.64              -
realized hedging activities
NGLs per Bbl, including impact of            32.53              -           35.66              -
realized hedging activities
Average sales price per Mcfe,
excluding impact of realized hedging   $      2.56     $     3.99     $      2.80     $     3.84
activities
Average sales price per Mcfe,
including impact of realized hedging          3.51           5.02            3.73           4.97
activities
Selected operating expenses (in
thousands):
Production taxes                       $       481     $      118     $       934     $      227
Lease operating expenses                     1,558          1,875           3,974          3,582
Transportation, treating and gathering       1,231          1,123           2,410          2,226
Depreciation, depletion and
amortization                                 6,956          2,991          12,609          7,103
Impairment of natural gas and oil
properties                                  72,733              -          72,733              -
General and administrative expense           3,151          2,596           6,312          5,476
Selected operating expenses per Mcfe:
Production taxes                       $      0.15     $     0.07     $      0.16     $     0.06
Lease operating expenses                      0.49           1.10            0.68           0.96
Transportation, treating and gathering        0.39           0.66            0.41           0.60
Depreciation, depletion and
amortization                                  2.20           1.76            2.16           1.91
General and administrative expense            0.99           1.53            1.08           1.47

Three Months Ended June 30, 2012 compared to the Three Months Ended June 30, 2011
Revenues. Total natural gas, oil and NGLs revenues were $11.1 million for the three months ended June 30, 2012, up from $8.5 million for the three months ended June 30, 2011. The increase in revenues was the result of an 87% increase in production offset by a 30% decrease in weighted average realized prices. Average daily production on an equivalent basis was 34.8 MMcfe/d for the three months ended June 30, 2012 compared to 18.6 MMcfe/d for the same period in 2011. Oil and NGLs daily production represented approximately 19% of total production for the three months ended June 30, 2012 compared to 16% of daily production for the three months ended March 31, 2012 and 4% of daily production for the prior year three month period, primarily as a result of our increased focus on drilling liquids-rich acreage in 2012.
Liquids revenues (oil, condensate and NGLs) represented approximately 40% of our total natural gas, oil and NGLs revenues for the three month period ended June 30, 2012 compared to 12% for the three month period ended June 30, 2011. Due to continued lower natural gas prices, we are focusing the majority of our 2012 drilling activity on the liquids-rich portions

of the Marcellus Shale. If current trends of natural gas prices relative to oil and NGLs prices continue, and assuming that we successfully and timely complete our 2012 drilling activity, we expect our liquids revenues to continue to increase as a percentage of total revenues before hedging gains or losses for the remainder of 2012. NGLs prices also declined during the second quarter of 2012, largely attributable to a record-warm winter, a slowing global economy and growing NGLs supplies. We expect NGLs prices to remain depressed in the near-term, with some anticipated recovery by the end of the year. During the three months ended June 30, 2012, we had commodity derivative contracts covering approximately 87% of our natural gas production, which resulted in realized gains of $2.3 million and an increase in total price realized from $1.70 per Mcf to $2.61 per Mcf. The realized hedge impact includes a benefit of $220,000 for amortization of prepaid call sale premiums. Excluding the non-cash amortization, the realized effect of hedging was an increase in revenues of $2.1 million, which was comprised of $3.1 million of NYMEX hedge gains offset by $12,000 of regional basis losses and payment of deferred put premiums of $1.0 million. During the three months ended June 30, 2011, the realized effect of hedging on natural gas sales was an increase of $1.7 million in natural gas revenues resulting in an increase in total price realized from $3.52 per Mcf to $4.59 per Mcf. The 2011 realized hedge impact included a benefit of $429,000 of non-cash amortization of prepaid call sale and put purchase premiums and payment of deferred put premiums of $686,000. During the three months ended June 30, 2012, we had commodity derivative contracts covering approximately 71% of our oil production. The realized effect of hedging on oil sales was an increase of $232,000 in oil revenues resulting in an increase in total price realized from $56.72 per Bbl to $62.76 per Bbl. During the three months ended June 30, 2012, we had commodity derivative contracts covering approximately 76% of our NGLs production. The realized effect of hedging on NGLs sales was an increase of $442,000 in NGLs revenues resulting in an increase in total price realized from $25.44 per Bbl to $32.53 per Bbl. Unrealized hedge gain was $2.8 million for the three months ended June 30, 2012 compared to $502,000 for the three months ended June 30, 2011. The increase in unrealized hedge gain is the result of lower future NYMEX gas prices and future oil and NGLs prices coupled with the addition of new future hedges. Production taxes. We reported production taxes of $481,000 for the three months ended June 30, 2012 compared to $118,000 for the three months ended June 30, 2011. The increase in production taxes primarily resulted from higher revenues in West Virginia due to increased natural gas, oil and NGLs production. Lease operating expenses. We reported lease operating expenses of $1.6 million for the three months ended June 30, 2012 compared to $1.9 million for the three months ended June 30, 2011. The decrease in our lease operating expenses ("LOE") was primarily due to a $321,000 decrease in controllable LOE and a $78,000 decrease in workover costs partially offset by an $81,000 increase in ad valorem taxes. The decrease in controllable LOE is primarily due to the assignment of our Powder River Basin properties to the operator on May 3, 2012. As a result of the assignment, Powder River Basin controllable LOE decreased $453,000 for the three months ended June 30, 2012 compared to the three months ended June 30, 2011. Our LOE was $0.49 per Mcfe for the three months ended June 30, 2012 compared to $1.10 per Mcfe for the same period in 2011.
Transportation, treating and gathering. We reported transportation expenses of $1.2 million for the three months ended June 30, 2012 compared to $1.1 million for the three months ended June 30, 2011, of which $931,000 and $1.0 million, respectively, related to our Hilltop operations in East Texas. The current quarter includes $484,000 of minimum volume requirement charges under our Hilltop gas gathering agreement compared to $411,000 of such charges in the same quarter of 2011. Such charges resulted from actual production volumes being less than minimum contractual volume requirements.
Depreciation, depletion and amortization. We reported depreciation, depletion and amortization ("DD&A") expense of $7.0 million for the three months ended June 30, 2012 up from $3.0 million for the three months ended June 30, 2011. The increase in DD&A expense was the result of a 25% increase in the DD&A rate per Mcfe and an 87% increase in production. The DD&A rate for the three months ended June 30, 2012 was $2.20 per Mcfe compared to $1.76 per Mcfe for the same period in 2011. The increase in the rate is primarily due to higher proved costs associated with the 2011 allocation of undeveloped East Texas leasehold costs from unproved to proved properties based on 2011 drilling results and reduced 2012 drilling activity.
Impairment of natural gas and oil properties. We reported an impairment of natural gas and oil properties of $72.7 million for the three months ended June 30, 2012. The impairment is primarily the result of a 24% decline in the 12-month average natural gas price used in the calculation of the full cost ceiling test at June 30, 2012 compared to the 12-month average natural gas price at December 31, 2011. We did not recognize an impairment for the three months ended June 30, 2011. Given the current price environment, we expect that further declines in the 12-month average natural gas, oil and NGLs prices will likely result in the recognition of future ceiling impairments.
General and administrative expense. We reported general and administrative expenses of $3.2 million for the three months ended June 30, 2012, up from $2.6 million for the three months ended June 30, 2011. Non-cash stock-based compensation expense, which is included in general and administrative expense, increased $416,000 to $954,000 for the three months ended June 30, 2012 compared to the three months ended June 30, 2011. The increase in stock-based compensation expense is

primarily due to the additional expense recognized during the period related to grants made in early 2012 that were in excess of grants made in the prior year. . . .