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GST > SEC Filings for GST > Form 10-Q on 7-Nov-2012All Recent SEC Filings

Show all filings for GASTAR EXPLORATION LTD

Form 10-Q for GASTAR EXPLORATION LTD


7-Nov-2012

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

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 September 30, 2012, our major assets consist of approximately 108,300 gross (75,500 net) acres in the Marcellus Shale in West Virginia and southwestern Pennsylvania, approximately 33,500 gross (17,100 net) acres in the Bossier play in the Hilltop area of East Texas and approximately 30,900 gross (12,500 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 nine months ended September 30, 2012 compared to the three and nine months ended September 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


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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 September 30, 2012, our acreage position in the play was approximately 108,300 gross (75,500 net) acres. We refer to the approximately 47,100 gross (21,000 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 61,200 gross (54,400 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 26 gross (12.7 net) wells during 2012. During the nine months ended September 30, 2012, we drilled and cased 16 gross (7.7 net) operated wells, completed fracture stimulation operations on 17 gross (8.0 net) operated wells and were in the process of fracture stimulating five gross (2.2 net) operated wells in Marshall County, West Virginia. We were also in various stages of drilling on 12 gross (6.0 net) operated wells in Marshall County, West Virginia. All of our 2012 Marcellus Shale well operations were under the Atinum Joint Venture. Effective 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 59% of the fluids used in its completion. Nearby vertical wells experienced low gas rates prior to recovering at least 75% of completion fluids. Due to low natural gas prices and in an effort to reduce operating costs, we are installing a pump jack 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.


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As of September 30, 2012, our operated wells capable of production in Marshall County, West Virginia were comprised of the following:

                                                                             Average
                                                                  Net        Lateral
              Gross Well                                        Revenue     Length (in
    Pad         Count      Net Well Count   Working Interest    Interest    feet) (1)      Status

Corley           4.0            1.6              40.8%           35.4%        4,900       Producing
Simms            3.0            1.5              50.0%           43.2%        5,000       Producing
Hall             3.0            1.2              40.0%           34.7%        4,400       Producing
Hendrickson      5.0            2.0              40.0%           34.7%        4,700       Producing
Accettolo        3.0            1.5              50.0%           40.2%        4,600       Producing
Burch Ridge      5.0            2.5              50.0%           41.5%        5,800       Producing
Wayne            4.0            2.0              50.0%           40.6%        5,700       Producing
Wengerd          2.0            0.9              44.5%           37.7%        5,200      Shut-in (2)
                 29.0           13.2


 _________________________________


(1) Average well lateral length approximates the actual average well lateral length.

(2) 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. We anticipate that these wells will be returned to production during December 2012 when the five additional Wengerd wells are turned to production.

As of September 30, 2012, we had drilling operations at various stages on the following wells in Marshall County, West Virginia:

                                                      Average
                                         Estimated    Lateral
           Gross      Net                   Net       Length                               Estimated
           Well      Well     Working     Revenue    (in feet)                            Production
  Pad      Count     Count    Interest   Interest       (1)              Status              Date

                                                                 Awaiting fracture        Early
Wengerd     5.0       2.2      44.5%       37.7%       5,000     stimulation/completion   December
                                                                                          2012
                                                                 One drilled to total     Late
Lily        4.0       2.0      50.0%       40.6%       5,100     depth; three drilled     December
                                                                 to kick off point        2012
                                                                 Eight drilled to kick    First and
Shields     9.0       4.5      50.0%       42.0%       2,800     off point; one drilled   Third
                                                                 to intermediate casing   Quarters
                                                                 point                    2013
           18.0       8.7


 _________________________________


(1) Average well lateral length approximates the actual average well lateral length for wells that have been completed and the estimated average well lateral length for wells that have not been completed.


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Currently, we have the following drilling operations in Marshall County, West Virginia:

                                                      Average
                                         Estimated    Lateral
           Gross      Net                   Net       Length                               Estimated
           Well      Well     Working     Revenue    (in feet)                            Production
  Pad      Count     Count    Interest   Interest       (1)              Status              Date

                                                                 Fracture stimulation     Early
Wengerd     5.0       2.2      44.5%       37.7%       5,000     completed; completion    December
                                                                 operations in progress   2012
                                                                 Fracture                 Late
Lily        4.0       2.0      50.0%       40.6%       5,100     stimulation/completion   December
                                                                 operations to begin      2012
                                                                 mid-November 2012
                                                                 Currently drilling       Second
Addison     5.0       2.5      50.0%       41.7%       5,000     top-holes                Quarter
                                                                                          2013
                                                                 Eight drilled to kick    First and
Shields    10.0       5.0      50.0%       42.0%       2,800     off point; one drilled   Third
                                                                 to intermediate casing   Quarters
                                                                 point                    2013
           24.0      11.7


 _________________________________


(1) Average well lateral length approximates the actual average well lateral length for wells that have been completed and the estimated average well lateral length for wells that have not been completed.

As of September 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. Currently, we do not plan to participate in any additional non-operated wells for the remainder of 2012 and 2013.
For the three and nine months ended September 30, 2012, net production from the Marcellus Shale averaged approximately 23.3 MMcfe/d and 19.4 MMcfe/d, respectively, compared to 2.9 MMcfe/d and 1.4 MMcfe/d for the three and nine months ended September 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, high line pressures and excessive unscheduled system down-time on a third-party-operated gathering system. The gathering system operator has been gradually resolving these issues and certain issues were resolved by late 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 third-party gathering system was down approximately 18.5% of the days in the third quarter of 2012 due to a fire at the facility in August 2012 and downstream NGLs processing plant curtailment in September 2012. The Burch Ridge CRP is currently scheduled to be operational by early December 2012 which should further reduce line pressure and limitations to dehydration capacity. If the Burch Ridge CRP is delayed, we may have to restrict our production in the fourth quarter of 2012 as the Wengerd pad is placed on production.
Hilltop Area, East Texas. At September 30, 2012, we held leases covering approximately 33,500 gross (17,100 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 nine months ended September 30, 2012, net production from the Hilltop area averaged approximately 14.6 MMcfe/d and 14.1 MMcfe/d, respectively, compared to 16.6 MMcfe/d and 17.9 MMcfe/d for the three and nine months ended September 30, 2011, respectively. The decrease 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. However, third quarter 2012 net production benefited by


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approximately 1.4 MMcfe/d primarily due to an increase in our Belin #1 net revenue interest based on an updated division order title opinion. Mid-Continent Horizontal Oil Play. At September 30, 2012, we held leases covering approximately 30,900 gross (12,500 net) acres in the previously announced non-operated Mid-Continent horizontal oil play. Our leasing activities are continuing in the initial AMI prospect area and have been expanded to include two additional adjacent prospect areas with a current goal of leasing at least 50,000 combined gross acres within the three prospect areas. For the first 12,500 gross acres acquired in the initial AMI prospect, we paid 62.5% of lease acquisition costs for a 50% leasehold interest and 50% of lease acquisition costs on additional acres in excess of 12,500 gross acres acquired for a 50% working interest. We will pay 54.25% of the lease acquisition costs in the two new prospect areas for a 50% working interest. In each prospect area, we pay 62.5% of the first four wells' gross drilling and completion costs and 56.25 % of the next four wells' gross drilling and completion costs to earn a 50% working interest. For all additional wells beyond the first eight in a prospect area, we are responsible for paying only the drilling and completion costs associated with our 50% working interest (approximate net revenue interest 39.0%). We are responsible for all leasing and permitting activities. In late July 2012, drilling operations commenced on the first of three wells to be drilled during 2012 on the initial prospect area. The first well has a horizontal lateral of approximately 4,200 feet and fracture stimulation operations were completed in late September 2012. Costs to drill and complete the first well are $4.4 million gross ($2.8 million net). Well flow back operations commenced on October 5, 2012 and the well continues to unload completion fluids with approximately 8% of frac fluid flowed back to date. Oil and natural gas production rates continue to increase. The operator plans to drill out the plugs between completion stages by mid-November 2012. The current oil and natural gas production is being sent to sales. Drilling operations on the second well are anticipated to commence by late November 2012 and the third well late in the fourth quarter 2012 on the initial prospect area. The two wells are scheduled to be on production in January and February 2013, respectively. 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 nine months ended September 30, 2012, Gastar USA sold 2,582,407 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $49.2 million, resulting in 3,946,950 total shares issued for net proceeds of $76.6 million at September 30, 2012. From October 1, 2012 to November 5, 2012, we sold an additional 4,304 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $84,000. 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.


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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 Months Ended        For the Nine Months Ended
                                               September 30,                     September 30,
                                            2012             2011            2012             2011
Production:
Natural gas (MMcf)                             2,783          1,837             7,584           5,437
Oil (MBbl)                                        42             10               106              31
NGLs (MBbl)                                       77              5               186               5
Total production (MMcfe)                       3,493          1,921             9,339           5,649
Total (Mmcfe/d)                                 38.0           20.9              34.1            20.7
Average sales price per unit:
Natural gas per Mcf, excluding impact  $        2.27     $     3.37     $        1.99     $      3.41
of realized hedging activities
Natural gas per Mcf, including impact           3.20           4.69              2.97            4.63
of realized hedging activities
Oil per Bbl, excluding impact of               76.54          77.64             68.93           87.91
realized hedging activities
Oil per Bbl, including impact of               83.05          77.64             72.93           87.91
realized hedging activities
NGLs per Bbl, excluding impact of              25.26          52.93             29.02           52.93
realized hedging activities
NGLs per Bbl, including impact of              32.40          52.93             34.31           52.93
realized hedging activities
Average sales price per Mcfe,
excluding impact of realized hedging   $        3.28     $     3.73     $        2.98     $      3.80
activities
Average sales price per Mcfe,
including impact of realized hedging            4.25           4.99              3.92            4.98
activities
Selected operating expenses (in
thousands):
Production taxes                       $         560     $      157     $       1,494     $       384
Lease operating expenses                         780          2,363             4,754           5,945
Transportation, treating and gathering         1,305          1,128             3,715           3,354
Depreciation, depletion and
amortization                                   7,135          3,694            19,744          10,797
Impairment of natural gas and oil
properties                                    78,054              -           150,787               -
General and administrative expense             2,951          3,100             9,263           8,576
Selected operating expenses per Mcfe:
Production taxes                       $        0.16     $     0.08     $        0.16     $      0.07
Lease operating expenses                        0.22           1.23              0.51            1.05
Transportation, treating and gathering          0.37           0.59              0.40            0.59
Depreciation, depletion and
amortization                                    2.04           1.92              2.11            1.91
General and administrative expense              0.84           1.61              0.99            1.52

Three Months Ended September 30, 2012 compared to the Three Months Ended September 30, 2011
Revenues. Total natural gas, oil and NGLs revenues were $14.8 million for the three months ended September 30, 2012, up from $9.6 million for the three months ended September 30, 2011. The increase in revenues was the result of an 82% increase in production offset by a 15% decrease in weighted average realized prices. Average daily production on an equivalent basis was 38.0 MMcfe/d for the three months ended September 30, 2012 compared to 20.9 MMcfe/d for the same period in 2011. Oil and NGLs production represented approximately 20% of total production for the three months ended September 30, 2012 compared to 19% and 16% of total production for the three months ended June 30, 2012 and March 31, 2012, respectively, and


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4% of total 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 September 30, 2012 compared to 10% for the three month period ended September 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 continued to decline during the third 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 September 30, 2012, we had commodity derivative contracts covering approximately 89% of our natural gas production, which resulted in realized gains of $2.6 million and an increase in total price realized from $2.27 per Mcf to $3.20 per Mcf. The realized hedge impact includes a benefit of $222,000 for amortization of prepaid call sale premiums. Excluding the non-cash amortization, the realized effect of hedging was an increase in revenues of $2.4 million, which was comprised of $3.5 million of NYMEX hedge gains offset by $49,000 of regional basis losses and payment of deferred put premiums of $1.1 million. During the three months ended September 30, 2011, the . . .

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